Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be “produced,” that is travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore.
Hydraulic fracturing is a primary tool for improving well productivity by placing or extending channels from the wellbore to the reservoir. This operation is essentially performed by hydraulically injecting a fracturing fluid into a wellbore penetrating a subterranean formation and forcing the fracturing fluid against the formation strata by pressure. The formation strata or rock is forced to crack or fracture. Proppant is placed in the fracture to prevent the fracture from closing and thus, provide improved flow of the recoverable fluid, i.e., oil, gas or water.
In conventional hydraulic fracturing, performed in low-permeability reservoir, the main objective is to generate lengthy and narrow fractures. On the other hand, in high-permeability reservoirs the treatment typically aims at generating a wide, short fracture packed with proppant to prevent the migration of fines often associated with poorly consolidated formations. This can be effectively achieved by promoting a tip-screenout (or TSO) event, i.e. by deliberately causing proppant to pack at a specific location thereby stopping fracture propagation.
A drawback of the fracturing jobs in high permeability formations is that they often result in high skins. The skin is the area of the formation that is damaged by the invasion of foreign substances, principally drilling fluids, during drilling and completion, including a fracturing treatment. With a guar-base fluid, the “foreign substances” are essentially the polymers or the residues left by the gel breakers, additives developed for reducing the viscosity of the gel at the end of the fracturing treatment by cleaving the polymer into small molecules fragments. These substances create a thin barrier, called a skin, between the well and the reservoir. This barrier causes a pressure drop around the wellbore that is quantified by the skin factor. Skin factor is expressed in dimensionless units: a positive value denotes formation damage; a negative value indicates improvement. Obviously, the higher the concentration of gelling agent, the greater the risk of damages and skins. In high permeability formation, this risk is a fortiori increased by the damage to the high proppant concentrations that are often used to obtain wider propped fractures. High skins can also result due to lack of not achieving a TSO.
In the case of low permeability formation, after the fracture initiation process, the shear rate becomes stable with a slightly decreasing trend. In contrast, in high permeability formation, the shear rate decreases drastically. The decrease in shear rate favors the use of lower guar concentrations; mainly because the viscosity of non-Newtonian crosslinked fluids increases with decrease in shear rate.
The differences in reservoir cooldown, and fluid shear rate lead to the need to provide improved methods of fracturing and propping a fracture especially in high permeability formations leading to lower skins and better control of the fracture geometry.